Combined miscible or near miscible gas and asp flooding for enhanced oil recovery

ABSTRACT

A method for enhancing oil recovery by combining miscible or near miscible gas flooding with Alkaline-Surfactant-Polymer (ASP) flooding to produce an enhanced Water-Alternating-Gas (WAG) flooding method is described. The ASP flooding may include individual and combination injections of alkaline, surfactant and polymer. Carbon dioxide may be used as a flood gas. Numerical simulations show that the present method may provide better oil recovery when compared with separate ASP or CO 2  WAG flooding for different depositional environments, as a result of high micro and macro sweep efficiencies plus miscible gas flooding. A significant acceleration and improvement in recovery may be achieved with as small as a 10% pore volume ASP slug size.

RELATED CASES

This application is the U.S. National Stage patent application of International Application No. PCT/US10/048,496, filed on Sep. 10, 2010, which claims the benefit of U.S. Provisional Patent Application Ser. No. 61/248,348 filed on 2 Oct. 2009 entitled “Combined Miscible Gas And ASP Flooding For Enhanced Oil Recovery” by Brian F. Towler, the disclosure and teachings of which are hereby incorporated by reference herein.

FIELD OF THE INVENTION

The present invention relates generally to enhanced oil recovery and, more particularly, to enhanced oil recovery using miscible gas flooding in combination with Alkaline-Surfactant-Polymer (ASP) flooding in oil reservoirs to produce an enhanced Water-Alternating-Gas (WAG) process.

BACKGROUND OF THE INVENTION

Water, alternating with miscible gas flooding or Water-Alternating-Gas (WAG) floods has found significant application as an effective enhanced oil recovery method. Both miscible and immiscible injections have been applied, and many different types of gas have been used. It has been found that the use of CO₂ and other miscible gases, such as ethane, propane, and butane, as examples, generates multi-contact and first contact miscibility with oil at reasonable reservoir pressures while other miscible gases may not reach this point unless very high pressures are applied. Although the microscopic sweep efficiency of carbon dioxide flooding is good, its macroscopic sweep efficiency is relatively poor due to phase segregation and unfavorable mobility ratio. However, the WAG gas injection scheme was originally proposed to tackle this shortcoming, mainly by using the water to control the mobility of the displacement and to stabilize the front.

The WAG injection combines the improved microscopic displacement efficiency of the gas flooding with an improved macroscopic sweep by water injection. This has resulted in improved recovery when compared with pure water injection or pure miscible gas injection. Other advantages of WAG injection include compositional exchanges which may give additional recovery and may influence the fluid densities and viscosities; and reinjection of gas may be desirable as result of environmental concerns, enforced restrictions on flaring, and CO₂ taxes.

Oil recovery, R_(f), can be described by three contributions:

R_(f)=E_(V)·E_(H)·E_(m), where E_(V)=vertical sweep, E_(H)=horizontal sweep, and E_(m)=microscopic displacement efficiency. The recovery can be optimized by maximizing any or all of these factors. In what follows the contributions of E_(V) and E_(H) will be called the macroscopic displacement efficiency. The horizontal displacement efficiency (E_(H)) will be strongly influenced by the stability of the front that is defined by the mobility of the fluids. The mobility ratio (M) can be described as M=(K_(rg)/μ_(g))/(K_(ro)/μ_(o)), where K_(rg) and K_(ro) are the relative permeabilities, and μ_(g) and μ_(o) are the viscosities for gas and oil, respectively. If an unfavorable mobility ratio is obtained; the gas will finger (or channel), causing early gas breakthrough and decreasing the sweep efficiency. Usually, gas is found to give early breakthrough; this is caused not only by the mobility ratio but also by the reservoir heterogeneity and especially highly permeable layers, as well as premature breakthrough of the water phase. The reservoir properties affecting the vertical sweep principally include reservoir dip angle and variation in permeability and porosity. Normally, porosity and permeability increasing downward will be advantageous for the WAG injection because this combination increases the stability of the front. In general the WAG displacement will be optimized if the mobility ratio is favorable (<1). Reduction of the mobility ratio can be obtained by increasing the gas viscosity or reducing the relative permeability of the fluids. Reduced mobility of the gas phase can be achieved by injecting water and gas alternately. Furthermore, the mobility is expected to be reduced when compared to gas injection. The amount of water and gas are adjusted to achieve efficient displacement. Too much water will result in poor microscopic displacement, while too much gas will result in poor vertical, and possibly horizontal, sweep.

The average improved recovery of WAG processes over waterflooding is determined to be about 10% for miscible WAG injection and about 6% for immiscible gas injection. The highest improved oil recovery is obtained in carbonate formations, and dolomites have higher predicted recoveries than the average for sandstones. As examples, CO₂ injection gas generates an average improved oil recovery of 10%, while methane and nitrogen have improved oil recovery of 8%. The higher recovery from CO₂ injections may result from its miscibility in many oil formations.

Increasing the CO₂ concentration may improve sweep efficiency, but it may destabilize asphaltenes, especially when the WAG ratio rises above 60%, leading to difficulties and disturbances in production.

WAG mobility control is not feasible in high or medium viscosity oil; however, it can be improved by using polymers to raise the aqueous phase viscosity. Moreover the microscopic sweep efficiency of the water slug can be improved if the interfacial tension (IFT) of the water/oil interface is reduced.

Water flooding enhanced with slugs of Alkali-Surfactant and -Polymer (ASP) flooding, is widely used as an effective enhanced oil recovery method. Many crude oil reservoirs produce their lowest IFT at low concentrations of alkali, typically about 0.2% sodium hydroxide, which produces the desired enhanced recovery effect. Concentrations above or below this range do not have as low IFT. However, such concentrations do not survive long in many reservoirs because of alkaline consumption by the rock, making propagation through the oil reservoir of such dilute alkaline solutions prohibitively slow. The choice between high displacement efficiency and satisfactorily displacement rate may be resolved by adding surfactant to the alkali. Low concentrations of a properly chosen surfactant raise the concentration of electrolytes required for minimum interfacial tension to alkali concentration, for the satisfactory propagation of the alkaline bank. That is, just as in chemical flooding, a surfactant can be used to raise the salinity requirement of an alkaline flood.

Alkali converts naphthalic acids in the crude oil to soaps. The combination of the soaps and a suitably chosen injected surfactant reduces the IFT to low values, where residual oil can be mobilized and oil trapping prevented, and it also reduces surfactant adsorption. Soaps are usually too lipophilic to produce low IFT at reservoir conditions. Hydrophilic surfactants can be injected in an alkaline-surfactant process at salinities below their optimal salinities for oil recovery when used in the absence of alkali.

At concentrations of alkali above that required to minimize interfacial tension, the excess alkali plays a similar role to that of excess salt. As stated, that problem may be solved by using a surfactant to increase the salinity requirement of the alkaline flooding system. However, oil production usually decreases more rapidly as salinity is increased to make a system over-optimum than when salinity is decreased to make the system under-optimum. The explanation of this asymmetry in oil recovery efficiency is twofold. First, as in chemical flooding, over-optimum systems lose more surfactant to the rock than do under-optimum systems. Second, an under-optimum slug, if not far under optimum, becomes optimum in the front mixing zone unless the pre-flood brine is much less saline than the slug brine. Over-optimum systems can become optimum if the system can be moved to an active region either by decreasing salinity or by decreasing water flood residual oil saturation. It has been found that little surfactant is needed to affect large improvements in oil recovery, and one of the reasons for anionic surfactants being effective at low concentration is that surfactant adsorption is lower at high pH.

Five mechanisms of enhanced oil recovery by alkaline flooding have been identified: (1) “Emulsification and Entrainment,” in which the crude oil is emulsified in-situ and entrained by the flowing aqueous alkali; (2) “Wettability reversal (oil wet to water wet),” in which oil production increases due to favorable change in permeabilities accompanying the change in wettability; (3) “Wettability reversal (water wet to oil wet),” in which residual oil saturation is attained through low interfacial tension and viscous water-in-oil emulsions working together to produce high viscous/capillary number; (4) “Emulsification and Entrapment,” in which sweep efficiency is improved by the action of emulsified oil droplets blocking the smaller pore throats; and (5) “Emulsification and Coalescence,” in which unstable water in oil emulsions forms spontaneously in the alkaline solution, then breaks to create local regions of high oil saturation with increased permeability to oil. Generally, alkaline flooding is viewed as a type of chemical flooding in which the surfactant is formed in-situ as the alkali converts petroleum acids in the crude oil to soaps.

Initially carbonate formations received less attention owing to a concern that the main surfactants being considered would form calcium and magnesium sulfonates that may either precipitate or partition into the oil phase. If sodium carbonate is used as the alkali and injected with a suitable anionic surfactant, the usual positive charge of carbonate rocks can be reversed with the result that surfactant adsorption is decreased and oil wet surfaces are modified to intermediate wet. Significant amounts of oil can be recovered from an initially mixed wet carbonate core placed in an imbibition cell containing a suitable aqueous solution of surfactant, sodium carbonate and sodium chloride. The wettability modification allows the surfactant solution to enter, and the resulting low interfacial tension reduces the capillary forces to the point that oil rises to the top of the core where it is released. No oil was recovered when a sodium chloride solution was instead used. Therefore, it is thought that such alkaline surfactant solutions can be injected into fractured carbonate formations to increase recovery.

SUMMARY OF THE INVENTION

Objects of embodiments of the present invention include enhancing oil recovery from reservoirs.

Additional objects, advantages and novel features of the invention will be set forth in part in the description which follows, and in part will become apparent to those skilled in the art upon examination of the following or may be learned by practice of the invention. The objects and advantages of the invention may be realized and attained by means of the instrumentalities and combinations particularly pointed out in the appended claims.

To achieve the foregoing and other objects, and in accordance with the purposes of the present invention, as embodied and broadly described herein, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: waterflooding at least a portion of the reservoir; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer; and flooding the pressurized portion of the reservoir with a solution containing alkali.

In another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: waterflooding at least a portion of the reservoir; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; waterflooding the pressurized portion of the reservoir; flooding the pressurized portion of the reservoir with a solution containing alkali; and flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.

In still another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: waterflooding at least a portion of the reservoir; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; waterflooding the pressurized portion of the reservoir; flooding the pressurized portion of the reservoir with a solution containing alkali; and flooding the pressurized portion of the reservoir with a solution containing at least one surfactant and at least one polymer.

In yet another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes that steps of: waterflooding at least a portion of the reservoir; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; and flooding the pressurized portion of the reservoir with a solution containing alkali, at least one surfactant and at least one polymer.

In another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: flooding at least a portion of the reservoir with an alkaline solution; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.

In still another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: flooding at least a portion of the reservoir with a solution containing at least one surfactant or at least one polymer; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and flooding the pressurized portion of the reservoir with a solution containing alkali.

In yet another aspect of the invention and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof includes the steps of: flooding at least a portion of the reservoir with a solution containing at least one surfactant and at least one polymer; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and flooding the pressurized portion of the reservoir with a solution containing alkali.

In another aspect of the invention, and in accordance with its objects and purposes, the method for enhancing oil recovery from reservoirs, hereof, includes the steps of: flooding at least a portion of the reservoir with a solution containing alkali, at least one surfactant and at least one polymer; pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and waterflooding the pressurized portion of the reservoir.

Benefits and advantages of the present invention include, but are not limited to generating increased oil recovery by combining the ASP and WAG methods, both methods having revealed enhanced oil recovery separately, by taking advantage of high micro/macro scale sweep efficiencies and yet further improvements in recovery if miscible gas flooding is achieved.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are incorporated in and form a part of the specification, illustrate the embodiments of the present invention and, together with the description, serve to explain the principles of the invention. In the drawings:

FIG. 1 is a graph of the percent Recovery Factor as a function of Normalized Elapsed Time for Alkaline-Surfactant-Polymer (ASP) flooding combined with miscible gas flooding (ASPaM) of the present invention, water alternating gas (WAG) flooding, CO₂ flooding, Pure Alkali-Surfactant-Polymer (PASP) flooding, ASP flooding, and water flooding (WF) oil recovery methods.

FIG. 2 is a graph of the percent Recovery Factor as a function of percent Pore Volume Injection using the combined ASPaM method in accordance with embodiments of the present invention, illustrating the effect of alkaline consumption by carbonic acid on the percent Recovery Factor.

FIG. 3 is a graph of the percent Recovery Factor as a function of percent Pore Volume Injection for the ASPaM, WAG, CO₂, ASP, and WF oil recovery methods, in a fining upward reservoir.

FIG. 4 is a graph of the percent Recovery Factor as a function of percent Pore Volume Injection for the ASPaM, WAG, ASP, WF, and CO₂ oil recovery methods, in a coarsing upward reservoir.

FIG. 5 is a graph of the percent Recovery Factor as a function of percent Pore Volume Injection for the CO₂, ASPaM, and WAG oil recovery methods, in randomly heterogeneous and homogeneous reservoirs.

DETAILED DESCRIPTION OF THE INVENTION

Briefly, the present invention includes a method of enhanced oil recovery that combines a miscible or near miscible gas flooding with a waterflood enhanced with slugs of alkali, surfactant and polymer. Miscible gases may include carbon dioxide, ethane, propane, butane and mixtures thereof, as examples. The term “near miscible” as used herein relates to situations where the gas flood occurs at pressures slightly below the miscible pressure, and the oil recovery from these processes is still high. As stated hereinabove, WAG injection improves gas injection sweeps, principally by using the water to control the mobility of the displacement, and to stabilize the front. Because the microscopic displacement of the oil by gas is normally better than that using water, the WAG injection combines the improved displacement efficiency of gas flooding with an improved macroscopic sweep by water injection. ASP flooding produces the lowest interfacial tension and highest displacing fluid viscosity which improves microscopic as well as macroscopic sweep efficiency. Therefore, combination of these two methods might reduce interfacial tension between phases and fingering over that for miscible flooding alone, and the reduction of residual oil saturation after miscible gas flooding might improve ASP performance.

Embodiments of the present ASP-WAG process include injection of gas into one or more injection wells following an initial waterflood, wherein oil trapped in the reservoir is released and swept towards at least one production well. After a period of gas injection effective for generating this result, slugs of alkali, surfactant and polymer solutions may be injected into the injection well, either individually or in various combinations, for releasing additional trapped oil from the reservoir and sweeping this oil towards the production wells. A waterflood may precede the injection of alkali in order to increase the pH of the reservoir after the gas injection if the oil miscible gas, CO₂, is used. After a further period, gas injection may be recommenced and ASP slugs are then alternated with the gas slugs until the process becomes uneconomical. Gas may also be injected between the individual alkali, surfactant and polymer solution slugs. The WAG ratio and the relative amounts of alkali, surfactant and polymer are determined a priori by laboratory experiments and/or numerical simulations. This present process may be performed with only one of the alkali, surfactant or polymer slugs, if the lab results suggest that this might be beneficial.

Water in the initial waterflood may be replaced by one or more of the ASP solutions, followed by injection of the miscible or near miscible gas or gases. If CO₂ is used as the miscible gas, a waterflood may precede subsequent alkali injections to raise the pH of the reservoir.

As stated hereinabove, gases suitable for miscible and near miscible gas injection may include carbon dioxide, ethane, propane, butane, and pentane, as examples. Surfactants and polymers useful in practicing ASP are well known, and are expected to be effective for the present ASPaM method.

In what follows, a process where gas injection follows waterflooding or flooding with chosen solutions, is, by definition, a WAG process. In the present invention the WAG process may be modified by using solutions of alkali, surfactant or polymer subsequent to the waterflood, or by eliminating the waterflooding step and following the gas injection by slugs of alkali, surfactants and polymers in various combinations. Miscible WAG, herein, includes gas/oil miscibility attained through multiple-contact of the oil with the gas.

The Water Alternating Gas (WAG) and Alkaline, Surfactant and Polymer (ASP) enhanced oil recovery methods individually have revealed promising results in field applications, but have not been applied together. In fact, these processes have been viewed as competitors. In the following simulation, the physics of oil displacement, rock and fluid, fluid and fluid interactions for both methodologies are individually investigated, and then applied in concert.

The present enhanced oil recovery method, termed ASPaM, has been developed and applied to a sector simulation using data from the South Slattery Field, Minnelusa A reservoir. As described hereinabove, the method, combines features of miscible gas flooding with Alkaline-Surfactant-Polymer (ASP) flooding to produce an enhanced WAG flood. A numerical pre-processor program was developed to produce the required mixing zone properties of a CO₂ front, which are input to the Computer Modeling Group, Inc. (CMG) chemical flood simulator, STARS. STARS is a chemical flood simulator, but cannot accommodate the solvent model. The pre-processor calculates oil and solvent properties based on the Todd-Longstaff procedure. Sensitivity analysis showed this new method may provide enhanced recovery when compared with ASP or CO₂ WAG flooding for different depositional environments. ASPaM benefits from high micro and macro sweep efficiencies plus miscible flooding, even for a small ASP slug size, and the simulation revealed that oil recovery using embodiments of the present invention the scheme is better than ASP and CO₂ flooding separately. It showed that the recovery is both improved and accelerated by the application of ASPaM, and its performance is a function of the miscibility of the CO₂-oil miscible zone and the reduction of the interfacial tension (IFT) at the ASP-oil interface at reservoir conditions. Moreover the water/gas ratio of ASPaM is different in scale when compared with a typical WAG scheme. For example, a significant acceleration and improvement in recovery may be achieved with a 10% pore volume ASP slug size which indicates that CO₂ flooding and sequestration can be stabilized and enhanced when combined with even a small ASP slug size.

Turning now to the simulation which is described in detail in “ASPaM, A New EOR Method,” by Towler, B. F., and Behzadi, S. H., SPE-123866, presented at the 2009 SPE Annual Technical Conference and Exhibition 4-7 Oct. 2009 in New Orleans, La., the disclosure and teachings of which paper are hereby incorporated by reference herein, as stated hereinabove, use data from the South Slattery Field in Wyoming, which has been previously studied by Sheppy (1986), Towler (1991) and Gao and Towler (2009). The South Slattery Field is a small Minnelusa field in the Powder River Basin with about 12 MMSTB oil in place. Different chemical flooding scenarios have been investigated for improving oil recovery in addition to an embodiment of the present method, ASP alternating with miscible CO₂ (ASPaM). Historical waterflood data has been matched and a chemical flood model was investigated, which included accounting for chemical adsorption, the residual resistance factor, surface tension as a function of the chemical concentration, and interpolation of relative permeability based on capillary number and solvent concentration. The South Slattery Field contains all of the conditions that CO₂ flooding requires; depth, temperature, oil gravity, porosity, permeability, etc. A continuous CO₂ injection was used for comparison in the simulation research. The existence of a density difference causes the CO₂ to distribute unevenly. The CO₂ sweep efficiency is low due to reservoir heterogeneity and unfavorable mobility ratio, which controls the volumetric sweep efficiency between the injected phase and displaced oil bank. It is known that waterflooding performance can be improved using ASP for reduction of capillary forces and of viscous fingering. Carbon dioxide gas flooding is a recognized and tested enhanced oil recovery method because of the high microscopic sweep efficiency thereof. Carbon dioxide readily dissolves in oil and reduces the oil viscosity, swells the oil and extracts the light components. However, as noted hereinabove, the volumetric sweep efficiency of CO₂ is poor.

Simulations have been performed comparing different enhanced oil recovery mechanisms; WAG, CO₂, ASP, WF (water flooding) and PASP (pure ASP flooding, with no chase water) flooding with ASPaM for different depositional environments. The sequence modeled for ASPaM was 10% ASP followed by a 10% CO₂ slug, followed by a waterflood and continuous CO₂ injection. For WAG the 10% ASP slug is substituted by water. The first depositional system is an isotropic and homogeneous reservoir. The recovery of ASPaM is clearly greater than the other schemes especially if time is considered as shown in FIG. 1. Here, Curve (a) represents the ASPaM results; Curve (b), WAG; Curve (c), CO₂; Curve (d), PASP; Curve (e), ASP; and Curve (f), WF (waterflooding). The simulation results show further that ASPaM generates less water in the production wells. Although PASP, which signifies pure ASP injection, shows greater recovery, it is not considered to be economically feasible since the production life is too long for the same recovery and cost of injection materials is high. The simulation also shows no significant influence of water slug size employed.

Consumption of alkali by carbonic acid may be important but, since ASP and CO₂ are injected alternatively, complete mixing is avoided and consequently the alkaline consumption is likely not significant. Alkaline consumption and gas/liquid mass transfer was simulated for a 2-D model, a diagonal of the sector model. FIG. 2 illustrates that there is no significant change in ultimate recovery if alkaline consumption is considered. Here, Curve (a) represents no alkaline consumption considered; and Curve (b) shows the results where alkaline consumption is considered.

Recovery using ASPaM was investigated in three heterogeneous systems: coarsening upward, fining upward and random-heterogeneity. The absolute permeability ratio of the overlaying strata in the coarsening upward system is 1/2/3 while in fining upward it is 3/2/1. ASPaM in both fining upward and coarsening upward shows better recovery than ASP and CO₂ flooding alone, while WAG has a similar performance to ASPaM in the fining upward deposition. However the recovery of both is greater than that for the homogenous system as shown in FIG. 3. Here, Curve (a), represents ASPaM; Curve (b), WAG; Curve (c), CO₂; Curve (d), ASP; and Curve (e), WF. The difference between the WAG and ASPaM performance increases for coarsening upward reservoirs when compared with a homogeneous system, which may be attributed to better micro sweep efficiency of the bottom layer in ASPaM, while for WAG, the miscible zone CO₂ front, is redirected to the upper layers, as illustrated in FIG. 4; thus, the bottom layer displacement is immiscible. In fining upward depositions, the miscible zone of CO₂ is redirected to bottom layers and improves the recovery of WAG. Here, Curve (a) represents ASPaM; Curve (b), WAG; Curve (c), ASP; Curve (d), WF; and Curve (e), CO₂. Therefore, the difference between them is reduced.

The ASPaM results were unexpected; that is, the recovery of ASPaM increased in these random-wise heterogeneities, while the recovery of WAG was reduced. Maps of the solvent saturation in the random system reveal its saturation in the deeper layers increases, which improves the recovery. At the same time the saturation of the trapped oil decreases due to multiphase flow and heterogeneity. The saturation of the trapped oil in the WAG process in heterogeneous systems is increased, due to interference with the positive effect of miscible displacement by CO₂. Heterogeneity generates two effects: it increases the saturation of trapped oil due to local trapping of the oil phase, which is a negative effect of heterogeneity; and it may have a positive effect by redirecting the solvent zone to the non-swept area. Based on these considerations it was expected that CO₂ flooding would give better results since less oil would be trapped by water. FIG. 5 shows the recovery of ASPaM, WAG and CO₂ for the homogeneous and two randomly heterogeneous depositions. Here, Curve (a) represents CO₂, Case 2; Curve (b), CO₂, Case 1; Curve (c), ASPaM, Case-1; Curve (d), ASPaM, Case-2; Curve (e), ASPaM; Curve (f), WAG; Curve (g), WAG, Case-2; Curve (h), WAG, Case-1; and Curve (i), CO₂. The recovery by CO₂ flooding, in the heterogeneous cases shows a sudden rise after 4 PV injections and overtakes the ASPaM after 9 PV for Case-2, and for Case-1 this occurs after another 3 PV of injection (12 PV).

In conclusion, the present method for enhanced oil recovery is a combination of the two commercial schemes, ASP and miscible flooding, and shows improvement in incremental recovery. In addition, ASPaM has fewer problems with injectivity, as well as generating less water in the production wells. Simulations show that heterogeneity does not significantly affect recovery, and may actually have a positive effect on recovery for fining upward depositions and randomly heterogeneous systems.

The foregoing description of the invention has been presented for purposes of illustration and description and is not intended to be exhaustive or to limit the invention to the precise form disclosed, and obviously many modifications and variations are possible in light of the above teaching. The embodiments were chosen and described in order to best explain the principles of the invention and its practical application to thereby enable others skilled in the art to best utilize the invention in various embodiments and with various modifications as are suited to the particular use contemplated. It is intended that the scope of the invention be defined by the claims appended hereto. 

1. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) waterflooding at least a portion of the reservoir; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; (c) flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer; and (d) flooding the pressurized portion of the reservoir with a solution containing alkali.
 2. The method of claim 1, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 3. The method of claim 1, further comprising the step of waterflooding the pressurized portion of the reservoir after said step of pressurizing the reservoir.
 4. The method of claim 1, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.
 5. The method of claim 1, further comprising the step of producing oil from the reservoir during said at least one of said steps.
 6. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) waterflooding at least a portion of the reservoir; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; (c) waterflooding the pressurized portion of the reservoir; (d) flooding the pressurized portion of the reservoir with a solution containing alkali; and (e) flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.
 7. The method of claim 6, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 8. The method of claim 6, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of flooding the pressurized portion of the reservoir with a solution containing alkali.
 9. The method of claim 6, further comprising the step of producing oil from the reservoir during at least one of said steps.
 10. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) waterflooding at least a portion of the reservoir; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; (c) waterflooding the pressurized portion of the reservoir; (d) flooding the pressurized portion of the reservoir with a solution containing alkali; and (e) flooding the pressurized portion of the reservoir with a solution containing at least one surfactant and at least one polymer.
 11. The method of claim 10, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 12. The method of claim 10, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of flooding the pressurized portion of the reservoir with a solution containing alkali.
 13. The method of claim 10, further comprising the step of producing oil from the reservoir during at least one of said steps.
 14. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) waterflooding at least a portion of the reservoir; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the waterflooded portion of the reservoir; and (c) flooding the pressurized portion of the reservoir with a solution containing alkali, at least one surfactant and at least one polymer.
 15. The method of claim 14, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 16. The method of claim 14, further comprising the step of waterflooding the pressurized portion of the reservoir after said step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil.
 17. The method of claim 16, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of waterflooding the pressurized portion of the reservoir.
 18. The method of claim 14, further comprising the step of producing oil from the reservoir during at least one of said steps.
 19. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) flooding at least a portion of the reservoir with an alkaline solution; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and (c) flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.
 20. The method of claim 19, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 21. The method of claim 19, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of flooding the pressurized portion of the reservoir with a solution containing at least one surfactant or at least one polymer.
 22. The method of claim 19, further comprising the step of producing oil from the reservoir during at least one of said steps.
 23. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) flooding at least a portion of the reservoir with a solution containing at least one surfactant or at least one polymer; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and (c) flooding the pressurized portion of the reservoir with a solution containing alkali.
 24. The method of claim 23, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 25. The method of claim 23, further comprising the step of waterflooding the pressurized portion of the reservoir after said step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil.
 26. The method of claim 23, further comprising the step of producing oil from the reservoir during at least one of said steps.
 27. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) flooding at least a portion of the reservoir with a solution containing at least one surfactant and at least one polymer; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and (c) flooding the pressurized portion of the reservoir with a solution containing alkali.
 28. The method of claim 27, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 29. The method of claim 27, further comprising the step of waterflooding the pressurized portion of the reservoir after said step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil.
 30. The method of claim 27, further comprising the step of producing oil from the reservoir during at least one of said steps.
 31. A method for enhancing oil recovery from reservoirs, comprising the steps of: (a) flooding at least a portion of the reservoir with a solution containing alkali, at least one surfactant and at least one polymer; (b) pressurizing the reservoir with a chosen gas miscible or near miscible with oil remaining behind the flooded portion of the reservoir; and (c) waterflooding the pressurized portion of the reservoir.
 32. The method of claim 31, wherein the chosen miscible or near miscible gas comprises carbon dioxide.
 33. The method of claim 31, further comprising the step of pressurizing the reservoir with a chosen gas miscible or near miscible with the remaining oil after said step of waterflooding the pressurized portion of the reservoir.
 34. The method of claim 31, further comprising the step of producing oil from the reservoir during at least one of said steps. 